Gran Tierra Energy GTE Form 10-Q filing Q2 FY2026

• PART I Financial Information
• Item 1. Financial Statements 3
• Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 22
• Item 3. Quantitative and Qualitative Disclosures About Market Risk 53
• Item 4. Controls and Procedures 54
• PART II Other Information
• Item 1. Legal Proceedings 55
• Item 1A. Risk Factors 55
• Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 55
• Item 5. Other information 55
• Item 6. Exhibits 56
• SIGNATURES 57

GLOSSARY OF OIL AND GAS TERMS

In this document, the abbreviations set forth below have the following meanings:

bbl barrel BOEPD barrels of oil equivalent per day

BOPD barrels of oil per day NGL natural gas liquids

NAR net after royalty boe barrels of oil equivalent

Sales volumes represent production NAR adjusted for inventory changes. Our oil and gas reserves are reported as NAR. Our production is also reported NAR, except as otherwise specifically noted as “working interest production before royalties”.

PART I - Financial Information

Item 1. Financial Statements

(See notes to the condensed consolidated financial statements)

(See notes to the condensed consolidated financial statements)

(See notes to the condensed consolidated financial statements)

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

(Expressed in U.S. Dollars, unless otherwise indicated)

1. Description of Business

Gran Tierra Energy Inc., a Delaware corporation (the “Company” or “Gran Tierra”), is a publicly traded company focused on oil and natural gas exploration and production with assets currently in Colombia, Ecuador and Canada.

2. Significant Accounting Policies

These interim unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of results for the interim periods.

The note disclosure requirements of annual audited consolidated financial statements provide additional disclosures required for interim unaudited condensed consolidated financial statements. Accordingly, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2025, included in the Company’s 2025 Annual Report on Form 10-K.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements, which are included in the Company’s 2025 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements. The Company has evaluated all subsequent events to the date these interim unaudited condensed consolidated financial statements were issued.

Recently Adopted Accounting Pronouncements

In July 2025, FASB issued ASU 2025-05 “Financial Instruments—Credit Losses: Amendments to the Measurement of Credit Losses on Certain Financial Assets”. This ASU provides a practical expedient for estimating expected credit losses on certain short-term receivables and contract assets arising from revenue transactions within the scope of ASC 606. Under the practical expedient, all entities may elect to assume that current conditions as of the balance sheet date would not change for the remaining life of the asset when developing reasonable and supportable forecasts. The ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2025, early adoption is permitted for both interim and annual reporting periods. The Company adopted this ASU effective January 1, 2026. The implementation of this update did not have a material impact on its balance sheet, statement of operations or financial statements disclosures.

Recently Issued Accounting Pronouncements

In May 2026, the FASB issued ASU 2026-02, Environmental Credits and Environmental Credit Obligations, which establishes guidance on the recognition, measurement, and disclosure of environmental credits and related obligations. The ASU requires entities to recognize qualifying environmental credits as assets measured at cost and to record environmental credit obligations as emissions occur, measured based on the carrying amount of credits held and the fair value of any additional credits required for settlement. The ASU is effective for annual reporting periods beginning after December 15, 2027, including interim periods within those years, with early adoption permitted. The Company is currently assessing the impact this update will have on its financial statements.

3. Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil and natural gas. The Company reports segmented information based on internal management reporting used by our Chief Operating Decision Makers (“CODM”), which are the Company’s Chief Executive Officer, Chief Financial Officer, Chief Operating Officer and Vice Presidents across various business functions. CODM allocates resources and assesses performance of each reportable segment based on segmented earnings. The Company determined three reportable segments based on the geographic organization: Colombia, Ecuador and Canada. The “Other” category represents the Company’s corporate activities.

The following tables present information on the Company’s reportable segments and other activities:

4. Taxes Receivable and Payable

The table below shows the break-down of taxes receivable, which are comprised of value added tax (“VAT”) and income tax receivables and payables:

(1) Included into other long-term liabilities on the Company’s condensed consolidated balance sheet.

The following table shows the movement of VAT and income tax receivables and payables for the period:

(1) VAT is paid on certain goods and services and collected on sales in Colombia at a rate of 19%.

5. Property, Plant and Equipment

(1) The “other” category includes right-of-use assets for operating and finance leases of $90.0 million, which had a net book value of $42.9 million as at June 30, 2026 (December 31, 2025 - $65.0 million, which had a net book value of $30.8 million).

During the three and six months ended June 30, 2026, the Company entered into three and four new finance leases related to power generation agreements in Ecuador and Colombia and recognized right-of-use assets of $5.3 million and $21.0 million, respectively, related to these agreements. During the six months ended June 30, 2026, the Company entered into one new operating office lease agreement in Colombia and recognized right-of-use asset of $4.0 million related to this agreement.

For the three and six months ended June 30, 2026 and 2025, the Company had no ceiling test impairment losses. The Company used a 12-month unweighted average of the first-day-of-the-month prices prior to the ending date of the period ended June 30, 2026 as follows: Brent Crude $78.55 per bbl, Edmonton Light Crude of C$98.28 per bbl, Alberta AECO spot price of C$1.55 per MMBtu, Edmonton Propane C$32.84 per boe, Edmonton Butane C$41.70 per boe and Edmonton Condensate C$100.06 per boe (June 30, 2025 as follows: Brent Crude of $73.60 per bbl, Edmonton Light Crude of C$91.55 per bbl, Alberta AECO spot price of C$1.69 per MMBtu, Edmonton Propane C$33.82 per boe, Edmonton Butane C$47.11 per boe and Edmonton Condensate C$95.75 per boe).

On June 30, 2026, the Company completed an asset exchange transaction in which it transferred a 30% working interest ("WI") in certain oil and natural gas rights, wells, and tangible assets located in the Marten Hills area, in exchange for oil and natural gas rights, wells, and tangible assets in the Seal/Dawson area, WI ranging from 35% to 100%. In connection with this transaction, the Company received cash consideration of C$0.8 million (US$0.6 million).

On June 23, 2026, the Company completed a disposition of 54% WI and associated title rights in the Lodgepole area in Canada effective January 1, 2026, for a total cash consideration of C$12.8 million (US$9.3 million). As part of disposition, the Company derecognized asset retirement obligation attributed to Lodgepole area totaling C$17.5 million (US$12.8 million) on an undiscounted basis and C$9.0 million (US$6.6 million) on a discounted basis. No gain or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.

On March 10, 2026, the Company completed the disposition of the entire WI and associated title rights in the Simonette Montney area in Canada effective January 1, 2026, for total cash consideration of C$66.3 million (US$48.6 million). No gain or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.

On March 17, 2026, the Company entered into a strategic partnership with Ecopetrol S.A. to earn, subject to regulatory approvals and conditions precedent, a 49% WI in the Tisquirama Block in Colombia. Under the terms of the agreement, the Company has committed to fund approximately $47.1 million of a $92.4 million gross capital program over 40 months, including a minimum Phase 1 investment of $15.0 million. Upon completion of Phase 1, the Company will be entitled to 49% of production and is expected to assume operatorship. On May 27, 2026, the Company satisfied all outstanding conditions precedent to the partnership agreement and received regulatory approval.

6. Debt and Debt Issuance Costs

The Company’s debt as at June 30, 2026, and December 31, 2025, was as follows:

(1) Includes $0.1 million of deferred financing fees related to Canadian revolving credit facility as at June 30, 2026 (December 31, 2025 - $1.8 million related to Canadian revolving and Colombian credit facilities).

(2) The current portion of the lease obligation was included in accounts payable and accrued liabilities on the Company’s condensed consolidated balance sheet and totaled $25.2 million as at June 30, 2026 (December 31, 2025 - $17.0 million).

Senior Notes

During the six months ended June 30, 2026, the Company issued $503.6 million in aggregate principal amount of its 9.75% Senior Secured Amortizing Notes due 2031 (the “9.75% Senior Notes”), and paid $125.0 million in cash consideration in exchange for $628.7 million aggregate principal amount of its 9.50% Senior Notes. The exchange was accounted for as a debt modification.

The 9.75% Senior Notes will mature on April 15, 2031, unless earlier redeemed or re-purchased. Subject to adjustment for required minimum denominations, the principal amount of 9.75% Senior Notes will be amortized over three installments as follows: (i) October 15, 2029 - 15% of the principal amount; (ii) October 15, 2030 - 15% of the principal amount; (iii) April 15, 2031 - the remainder of the principal amount. On or before December 31, 2026 (“the Offer Date”), the Company is required to offer to purchase up to $30.0 million aggregate principal amount of the 9.75% Senior Notes (“the Offer Amount”). The Offer Amount will be reduced by the aggregate principal amount of any 9.75% Senior Notes redeemed or re-purchased by the Company in the open market transactions before the Offer Date.

During the six months ended June 30, 2026, the Company re-purchased $9.2 million of 9.75% Senior Notes for cash consideration of $8.1 million resulting in a $0.6 million gain on purchase, which included the write-off of deferred financing fees of $0.5 million. Subsequent to the quarter, the Company re-purchased an additional $15.0 million of 9.75% Senior Notes for cash consideration of $13.5 million.

At any time, prior to April 15, 2028, the Company may redeem up to 35% of the aggregate principal amount of 9.75% Senior Notes at a redemption price equal to 109.75% of the principal amount. Additionally, the Company may redeem all or a portion of the 9.75% Senior Notes on or after 2028 at the following redemption prices: 2028 - 104.875%; 2029 - 102.438%; 2030 and thereafter - 100%.

Under the terms of the 9.75% Senior Notes agreement, the Company is required to maintain compliance with the following financial covenants:

i.consolidated interest coverage ratio of not less than 2.50; and

ii.consolidated net debt (total debt excluding deferred financing fees less cash equivalents) to consolidated adjusted earnings before interest, taxes and DD&A (“EBITDA”) of not more than 3.00.

As at June 30, 2026, the Company was in compliance with all applicable covenants related to Senior Notes.

Credit facility

On May 12, 2026, the Company, through its wholly owned subsidiary Gran Tierra Canada Ltd., amended its revolving credit facility with National Bank of Canada. As part of the amendment, the borrowing base has decreased to C$75.0 million (US$52.8 million). The available commitment under the revolving credit facility remained unchanged of a C$75.0 million (US$52.8 million), comprised of a C$60.0 million (US$42.3 million) syndicated facility and C$15.0 million (US$10.6 million) of operating facility. The amounts drawn down under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00% to 4.00% per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00% to 5.00% per annum. Undrawn amounts under the revolving credit facility bear a standby fee ranging from 0.75% to 1.25% per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd. The revolving credit facility matures on October 30, 2027. As of June 30, 2026, the revolving credit facility remained undrawn.

Leases

During the three and six months ended June 30, 2026, the Company entered into three and four finance leases of $5.3 million and $21.0 million, respectively. The new finance leases had a three-year term and a weighted average discount rate of 9.6%.

During the six months ended June 30, 2026, the Company entered into one operating lease of $4.0 million which had a five-year term and a discount rate of 9.1%.

Interest Expense

The following table presents the total interest expense recognized in the accompanying interim unaudited condensed consolidated statements of operations:

7. Prepayment agreements

During the six months ended June 30, 2026, the Company amended its existing prepayment agreement with Trafigura. The amended agreement provides for total prepayments of up to $350.0 million, including $325.0 million available immediately and an additional $25.0 million available at Trafigura’s sole discretion and includes both Ecuadorian and Colombian crude oil production. The term of the amended prepayment agreement is 48 months.

Amounts drawn on this prepayment agreement are to be repaid through future oil deliveries. Shortfalls in crude oil deliveries in any given repayment period can be delivered during the next repayment period within three calendar months or paid in cash thereafter. Amounts under the prepayment facility are subject to interest based on SOFR risk-free rate plus a margin of 4.45% per annum. Under the terms of the prepayment agreement, the Company can repay the outstanding balance of the advance payment at any time without penalty. The Company was granted a grace period for re-payment of the principal amount drawn under the prepayment agreement with first re-payment starting April 2026.

Pursuant to the amended and restated prepayment agreement, proceeds from the new advance are required to be used exclusively to finance the re-purchase or exchange of Senior Notes and to pay fees and expenses associated with the amended agreement.

The Company is required to maintain compliance with the following financial covenants related to amounts drawn under the prepayment agreement semi-annually, calculated on March 31 and September 30 of each year:

i.Asset Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of certain wholly owned subsidiaries of the Company that sell crude oil, projected through the final maturity date and discounted at 10% over the outstanding principal and the interest payable amount on the prepayment agreement at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 90% of the prevailing ICE Brent forward strip.

ii.Debt Service Coverage Ratio of at least 200%, calculated using the estimated crude oil to be delivered by the Company from any relevant time up to the final maturity date based on 80% of the prevailing ICE Brent forward strip and adjusted for quality differential and transportation discount over the outstanding principal amount under the prepayment agreement.

As at June 30, 2026, there was $287.7 million outstanding (December 31, 2025 - $150.0 million) on the oil prepayment agreement. Of this amount, $86.3 million (December 31, 2025 - $34.1 million) was classified as a current portion and included in accounts payable and accrued liabilities on the Company’s condensed consolidated balance sheet.

During the three and six months ended June 30, 2026, the Company drew nil and $166.5 million on oil prepayment and re-paid $28.8 million of the outstanding principal on oil prepayment via crude oil deliveries.

As of June 30, 2026, the Company was in compliance with all applicable covenants under the prepayment agreement.

8. Share Capital

As at June 30, 2026, the Company had a share re-purchase program (the “2025 Program”) through the facilities of the Toronto Stock Exchange (“TSX”), the NYSE American or alternative programs in Canada or the United States, if eligible. Under the 2025 Program, the Company is able to purchase up to 2,925,720 shares of Common Stock, par value of $0.001 per share (“Common Stock”) representing 10% of the public float as of October 31, 2025, at prevailing market prices at the time of purchase. The 2025 Program will continue for one year and expire on November 5, 2026, or earlier if the 10% maximum is reached.

During the three and six months ended June 30, 2026, the Company did not re-purchase any shares under the 2025 Program (three and six months ended June 30, 2025 - 239,754 and 692,804 shares re-purchased under the 2024 program at a weighted average price of $4.38 and $5.00 per share, respectively).

Equity Compensation Awards

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted share units (“RSUs”) and stock option activity for the six months ended June 30, 2026:

As at June 30, 2026, the equity compensation award liability on the Company’s balance sheet included $1.0 million of current liability related to the Company’s outstanding stock options (December 31, 2025 - $0.6 million).

For the three and six months ended June 30, 2026, there was $3.8 million of stock-based compensation recovery and $15.9 million of stock-based compensation expense, respectively. For the three and six months ended June 30, 2025, stock-based compensation expense was $0.5 million and nil, respectively.

As at June 30, 2026, there was $43.6 million (December 31, 2025 - $15.4 million) of unrecognized compensation costs related to unvested PSUs, RSUs and stock options, which are expected to be recognized over a weighted-average period of 2.0 years. During the six months ended June 30, 2026, the Company paid out $6.0 million for PSUs which vested on December 31, 2025 (six months ended June 30, 2025 - $7.2 million for PSUs which vested on December 31, 2024).

During the three and six months ended June 30, 2026, the Company awarded nil and 1.0 million of RSUs to employees pursuant to the existing 2007 Equity Incentive Plan, respectively. Under the 2007 Equity Incentive Plan, RSUs will vest one-third each year over a three-year period. Upon vesting, RSUs entitle the holder to receive either the underlying number of shares of the Company’s Common Stock or a cash payment equal to the value of the underlying shares of the Company’s Common Stock. The Company intends to settle RSUs outstanding as at June 30, 2026, in cash.

Net Income (Loss) per Share

Basic net income or loss per share is calculated by dividing net income or loss attributable to common shareholders by the weighted average number of shares of Common Stock issued and outstanding during each period.

Diluted net income or loss per share is calculated using the treasury stock method for share-based compensation arrangements. The treasury stock method assumes that any proceeds obtained on the exercise of share-based compensation arrangements would be used to purchase shares of Common Stock at the average market price during the period. The weighted average number of shares is then adjusted by the difference between the number of shares issued from the exercise of share-based compensation arrangements and shares re-purchased from the related proceeds. Anti-dilutive shares represent potentially dilutive securities excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

Weighted Average Shares Outstanding

For the three and six months ended June 30, 2026 and 2025, all options were excluded from the diluted earnings (loss) per share calculation as the options were anti-dilutive.

9. Revenue

During the three and six months ended June 30, 2026, the Company’s production was sold primarily to one major customer, representing 69% and 71% of the total Company’s sales volumes (three and six months ended June 30, 2025 - one major customer, representing 64% and 65% of the total Company’s sales volumes), respectively, reported in each of the reportable segments.

As at June 30, 2026, accounts receivable included $10.9 million of accrued sales revenue related to June 2026 production (December 31, 2025 - $14.8 million related to December 2025 production).

10. Taxes

The Company’s effective tax rate was 6% for the six months ended June 30, 2026, compared to a negative 34% in the corresponding period of 2025.

Current income tax expense was $15.0 million for the six months ended June 30, 2026, compared to $10.5 million in the corresponding period of 2025, primarily due to higher taxable income.

For the six months ended June 30, 2026, the Company recognized a deferred tax recovery of $21.1 million, primarily attributable to an increase in deductible temporary differences arising from tax losses generated during the period, unrealized hedging losses and accruals. This recovery was partially offset by temporary differences related to accelerated tax depreciation in excess of accounting depreciation.

For the six months ended June 30, 2025, the deferred income tax recovery of $2.3 million was primarily attributable to an increase in deductible temporary differences arising from tax losses generated during the period. This recovery was partially offset by temporary differences related to accelerated tax depreciation in excess of accounting depreciation.

For the six months ended June 30, 2026, the difference between the effective tax rate of 6% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments and other non-deductible expenses. This was partially offset by an increase in the impact of foreign taxes and the 2025 true-up (recovery).

For the six months ended June 30, 2025, the difference between the effective tax rate of negative 34% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments, other permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes.

11. Contingencies

Legal Proceedings

The Company has several lawsuits and claims pending. The outcome of the lawsuits and disputes cannot be predicted with certainty; the Company believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows. The Company records costs as they are incurred or become probable and determinable.

Letters of Credit and Other Credit Support

At June 30, 2026, the Company had provided letters of credit and other credit support totaling $222.5 million, of which $39.1 million was related to capital commitments in the Suroriente Block which were completed by the end of the quarter and $0.5 million related to transportation capacity in Canada with the remainder as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, other capital or operating requirements (December 31, 2025 - $209.0 million).

12. Financial Instruments and Fair Value Measurement

Financial Instruments

Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to market participants to settle liability at the measurement date. For financial instruments carried at fair value, GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels:

• Level 1 - Inputs representing quoted market prices in active markets for identical assets and liabilities
• Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the assets and liabilities, either directly or indirectly
• Level 3 - Unobservable inputs for assets and liabilities

At June 30, 2026, the Company’s financial instruments recognized on the balance sheet consist of cash and cash equivalents, accounts receivable, derivatives, other long-term assets, accounts payable and accrued liabilities, current portion of long-term debt, long-term debt and other long-term liabilities. The Company uses appropriate valuation techniques based on the available information to measure the fair values of assets and liabilities.

Fair Value Measurement

The following table presents the Company’s fair value measurements of its financial instruments as of June 30, 2026, and December 31, 2025:

(1) The long-term portion of restricted cash and cash equivalents is included in the other long-term assets on the Company’s condensed consolidated balance sheet.

The fair values of cash and cash equivalents, current restricted cash and cash equivalents, accounts receivable and accounts payable, and accrued liabilities approximate their carrying amounts due to the short-term maturity of these instruments.

Restricted Cash and Cash Equivalents - Long-Term

The fair value of long-term restricted cash and cash equivalents approximate its carrying value because interest rates are variable and reflective of market rates.

Senior Notes

Financial instruments recorded at amortized cost at June 30, 2026, were the Senior Notes (Note 6).

At June 30, 2026, the carrying amounts of the 7.75% Senior Notes, 9.50% Senior Notes and 9.75% Senior Notes were $24.1 million, $83.9 million and $467.3 million, respectively, which represented the aggregate principal amounts less unamortized debt issuance costs and discounts, and the fair values were $22.7 million, $83.3 million and $433.8 million, respectively.

Derivative asset and derivative liability

The fair value of derivatives is estimated based on various factors, including quoted market prices in active markets and quotes from third parties. The Company also performs an internal valuation to ensure the reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers whether such counterparty has the ability to meet its potential repayment obligations associated with the derivative transactions.

Commodity Price Risk

The Company may at times utilize commodity price derivatives to manage the variability in cash flows associated with the forecasted sale of its oil production, reduce commodity price risk and provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending. As at June 30, 2026, the Company had outstanding commodity price derivative positions in Canada and Colombia as follows:

Foreign Exchange Risk

The Company is exposed to foreign exchange risk arising from Colombian and Canadian operations predominantly related to operating and transportation costs. Revenue and general and administrative expenses associated with the Company’s Canadian operations are also subject to foreign currency fluctuations. To mitigate exposure to fluctuations in foreign exchange, the Company may enter into foreign currency exchange derivatives.

As at June 30, 2026, the Company had the following outstanding foreign currency exchange derivative positions:

(1) At June 30, 2026 foreign exchange rate.

13. Supplemental Cash Flow Information

The following table provides a reconciliation of cash and cash equivalents and restricted cash and cash equivalents shown as a sum of these amounts in the interim unaudited condensed consolidated statements of cash flows:

(1) Included in other long-term assets on the Company’s condensed consolidated balance sheet.

Net changes in assets and liabilities from operating activities were as follows:

Net changes in working capital from investing activities were as follows:

The following table provides additional supplemental cash flow disclosures:

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of our financial condition and results of operations should be read in conjunction with the “Financial Statements” as set out in Part I, Item 1 of this Quarterly Report on Form 10-Q, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the “Financial Statements and Supplementary Data” included in Part II, Items 7 and 8, respectively, of our 2025 Annual Report on Form 10-K. Please see the cautionary language at the beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements and the risk factors described in Part II, Item 1A “Risk Factors” of this Quarterly Report on Form 10-Q, as well as Part I, Item 1A “Risk Factors” in our 2025 Annual Report on Form 10-K.

Financial and Operational Highlights

Key Highlights for the second quarter of 2026

• Net income for the second quarter of 2026 was $24.9 million or $0.70 per share basic and diluted, compared to a net loss of $12.7 million or $(0.36) per share basic and diluted for the second quarter of 2025 and a net loss of $119.2 million or $(3.38) per share for the prior quarter.
• Income before income taxes for the second quarter of 2026 was $45.3 million, compared to loss before income taxes of $8.1 million for the second quarter of 2025 and loss before income taxes of $145.8 million for the prior quarter
• Brent oil price averaged $96.68 per bbl during the quarter, an increase of 45% from the comparative period of 2025, and an increase of 23% from the prior quarter. Castilla, Vasconia and Oriente differentials averaged $9.71, $1.42 and $2.01 per bbl during the quarter, an increase of 105% for Castilla and a decrease of 17% and 72% for Vasconia and Oriente differentials from the comparable period of 2025. Castilla differential was comparable to the prior quarter and Vasconia and Oriente differentials decreased by 76% and 75% from the prior quarter, respectively
• Adjusted EBITDA(2) was $85.1 million for the second quarter of 2026, an increase from $77.0 million in the second quarter of 2025, and $73.9 million in the prior quarter
• Funds flow from operations(2) increased to $60.3 million compared to $53.9 million in the second quarter of 2025, and $42.8 million in the prior quarter
• NAR production for the second quarter of 2026 decreased by 20% to 31,990 BOEPD, compared to 39,800 BOEPD in the second quarter of 2025, and decreased by 15% from 37,741 BOEPD in the prior quarter primarily due to lower production in Colombia, higher in-kind royalties driven by higher oil prices and asset sales in Canada
• NAR sales volumes for the second quarter of 2026 decreased by 16% to 32,166 BOEPD, compared to 38,331 BOEPD in the second quarter of 2025 and decreased by 20% from 40,267 BOEPD in the prior quarter
• Oil, natural gas and NGL sales for the second quarter of 2026 increased by 25% to $187.2 million, compared to the second quarter of 2025, due to increase in benchmark oil prices, offset by lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia associated with using alternative transportation routes for Putumayo production as the Colombia and Ecuador border remained closed. Oil, natural gas and NGL sales increased by 9% from $172.1 million in the prior quarter due to higher benchmark oil prices and lower quality and transportation discounts in Colombia and premium in Ecuador, partially offset by lower sales volumes
• Operating expenses decreased by 7% and 22% to $51.6 million when compared to the second quarter of 2025 and the prior quarter, respectively, primarily due to lower workover activities, reduced field personnel costs, lower oil treatment and testing service costs, as well as inventory fluctuations resulting from inventory accumulation at the end of the current quarter. On a per boe basis, operating expenses increased by $1.67 to $17.61 when compared to the second quarter of 2025 due to lower sales volumes and decreased by $0.64 from $18.25 in the prior quarter primarily due to inventory fluctuations resulting from inventory accumulation at the end of the current quarter
• Transportation expenses decreased by 13% when compared to the second quarter of 2025 and decreased by 26% from the prior quarter primarily due to lower sales volumes transported in Colombia and Canada
• Gross profit increased to $75.5 million compared to $23.3 million in the second quarter of 2025 and $36.7 million in the prior quarter
• Operating netback(2) was $131.7 million compared to $89.3 million in the second quarter of 2025 and $100.6 million in the prior quarter
• Quality and transportation discounts per boe in South America were $10.47, an increase from $10.29 in the second quarter of 2025 due to higher transportation discounts in Colombia. Quality and transportation discounts in Colombia were affected by using alternative transportation route for Putumayo production as a result of closure of Ecuador and Colombia border which was significantly more expensive and resulted in approximately $5.9 million for the current

quarter. Quality and transportation discounts in South America decreased from $19.04 per boe in the prior quarter primarily a result of decrease in Vasconia and Oriente differentials, offset by higher transportation discounts

• Quality and transportation discounts for oil per boe in Canada for the second quarter of 2026 decreased to $2.24 compared to $8.22 in the second quarter of 2025 and $9.70 in the prior quarter due to lower pipeline tariffs in the current quarter resulting from a change in product mix associated with asset sales
• General and administrative (“G&A”) expenses before stock-based compensation for the second quarter of 2026 decreased to $13.2 million compared to $14.1 million in the second quarter of 2025 and $15.1 million in the prior quarter due to lower consulting, information technology costs and lower salaries associated with headcount optimization
• Capital expenditures for the second quarter of 2026 were $54.3 million compared to $51.2 million in the second quarter of 2025 and $45.4 million in the prior quarter
• During the second quarter, we satisfied all outstanding conditions precedent to and received regulatory approval for a strategic partnership with Ecopetrol S.A., earning a 49% working interest in the Tisquirama Block in Colombia. Additionally, we completed all capital commitments related to Suroriente Block.

(1) Sales volumes represent production NAR adjusted for inventory changes.

(2) Non-GAAP measures.

Gross profit is derived from oil, gas and NGL sales, less operating and transportation expenses, and depletion and accretion related to producing assets. Gross profit does not include depreciation of administrative assets, asset impairment, general and administrative expenses, interest, taxes or other non-operating items.

Operating netback, EBITDA, adjusted EBITDA, and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to oil sales, net income (loss) or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Disclosure of each non-GAAP financial measure is preceded by the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.

Operating netback, as presented, is defined as gross profit adjusted for depletion and accretion related to producing assets. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from gross profit to operating netback is provided in the table below.

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $43.5 million and $50.5 million less depreciation of administrative assets of $5.5 million and $2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million, less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $46.4 million, less depreciation of administrative assets of $5.7 million.

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $10.3 million and $4.4 million less depreciation of administrative assets of $0.6 million and nil, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $26.3 million and $14.8 million less depreciation of administrative assets of $0.7 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $16.0 million, less depreciation of administrative assets of $0.1 million.

(*) Same as DD&A expenses for the three months ended June 30, 2026 and 2025, six months ended June 30, 2026 and 2025, and the prior quarter (the depreciation of administrative assets had a de minimus amount for all reported periods).

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $62.3 million and $68.6 million less depreciation of administrative assets of $6.1 million and $2.7 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $132.2 million and $140.8 million less depreciation of administrative assets of $12.0 million and $6.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $69.9 million, less depreciation of administrative assets of $6.0 million.

EBITDA, as presented, is defined as net income (loss) adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense, and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for severance expense, non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense or recovery, other non-cash gains or losses and unrealized derivative instruments gains or losses. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is a useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to EBITDA and adjusted EBITDA is as follows:

Funds flow from operations, as presented, is defined as net income (loss) adjusted for DD&A expenses, deferred income tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, Senior Notes exchange fees, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, unrealized derivative instruments gains or losses and other non-cash gains or losses. Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net loss to funds flow from operations is as follows:

Additional Operational Results

(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition of this measure.

Oil, Natural Gas and NGL Production and Sales Volumes, BOEPD

Oil, natural gas and NGL production NAR for the three and six months ended June 30, 2026, decreased by 20% and 11% to 31,990 BOEPD and 34,850 BOEPD, respectively, compared to the corresponding periods of 2025 due to lower production in Colombia, higher in-kind royalties driven by higher oil prices and the sale of Simonette area in Canada at the end of prior quarter, partially offset by higher than anticipated production results from Conejo-1 well in Charapa Block and additional production from Perico Block in Ecuador acquired in December 2025. Oil, natural gas and NGL production NAR decreased by 15% compared to the prior quarter primarily due to the sale of the Simonette area in Canada and lower production in the Acordionero and Cohembi fields in Colombia as a result of failure of artificial lift systems.

Royalties as a percentage of production for the three and six months ended June 30, 2026 increased to 23% and 20%, respectively, compared to the corresponding periods of 2025 and the prior quarter as a result of higher benchmark oil prices and the price sensitive royalty regime in Colombia and Ecuador.

The Midas Block includes the Acordionero field, the Suroriente Block includes the Cohembi field, and the Chaza Block includes the Costayaco and Moqueta fields. Ecuador includes the Charapa, Iguana, Chanangue and Perico Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with the majority of production in Alberta, Canada.

Commodity prices:

Colombia and Ecuador

Brent - For the three and six months ended June 30, 2026, Brent increased 45% and 24% from the corresponding periods of 2025 and increased 23% from the prior quarter.

For the three months ended June 30, 2026, Castilla differential per bbl increased to $9.71 from $4.73 in the corresponding period of 2025. Vasconia and Oriente differentials per bbl decreased to $1.42 and $2.01 compared to $1.71 and $7.26, respectively, in the corresponding period of 2025.

For the six months ended June 30, 2026, Castilla and Vasconia differentials per bbl increased to $9.69 and $3.65 from $5.04 and $1.99, respectively, in the corresponding period of 2025. Oriente differential per bbl decreased to $5.07 from $7.45 in the corresponding period of 2025.

Castilla differential per bbl was comparable to the prior quarter and Vasconia and Oriente differentials per bbl decreased from $5.91 and $8.17 in the prior quarter.

The differentials for South America fluctuate based on regional supply and demand of heavy crude, shipping costs, pipeline disruptions and geopolitical and trading policies.

During the three and six months ended June 30, 2026 and 2025, 100% of sales from South America was priced against Brent.

Canada

WTI - For the three and six months ended June 30, 2026, WTI increased by 45% and 22% from the corresponding periods of 2025 and increased 27% from the prior quarter. During the three and six months ended June 30, 2026, 22% and 23% of NAR production in Canada was oil, compared to 26% and 23% for the corresponding periods of 2025 and 25% in the prior quarter, respectively.

NGLs - For the three and six months ended June 30, 2026, the weighted average NGL price received was 7% and 12% of WTI compared to 11% and 12% of WTI in the corresponding periods of 2025, respectively, and 10% of WTI in the prior quarter. During the three and six months ended June 30, 2026, NGLs production in Canada was 27% in each reporting period, and comparable to the corresponding periods of 2025 and the prior quarter.

AECO - For the three and six months ended June 30, 2026, AECO price decreased by 3% and 5% from the corresponding periods of 2025 and decreased 19% from the prior quarter. During the three and six months ended June 30, 2026, 52% and 50% of production in Canada was natural gas, compared to 50% and 51%, in the corresponding periods of 2025, respectively, and 49% in the prior quarter.

Oil, natural gas and NGL sales for the three and six months ended June 30, 2026, increased by 25% and 13% to $187.2 million and $359.2 million compared to the corresponding periods of 2025, primarily due to increases of 45% and 24% in Brent price, partially offset by 16% and 6% lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia. Quality and transportation discounts in Colombia were affected by using alternative transportation route for Putumayo production as Colombia and Ecuador border remained closed. The alternative transportation route was significantly more expensive and resulted in approximately $5.9 million and $10.0 million for the three and six months ended June 30, 2026.

Compared to the prior quarter, oil, natural gas and NGL sales increased by 9%, primarily due to a 23% increase in Brent price and lower quality and transportation discounts in Colombia and premium in Ecuador, partially offset by a 20% decrease in sales volumes. During three months ended June 30, 2026, there was only one lifting in Ecuador compared to two in the prior quarter.

The following table shows the effect of changes in realized price and sale volumes on our oil, natural gas and NGL sales for the three and six months ended June 30, 2026, compared to the prior quarter and the corresponding periods of 2025:

Gross Profit

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $43.5 million and $50.5 million less depreciation of administrative assets of $5.5 million and $2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million

less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $46.4 million, less depreciation of administrative assets of $5.7 million.

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $10.3 million and $4.4 million less depreciation of administrative assets of $0.6 million and nil, respectively. For the six months ended June 30, 2026 and 2025. DD&A expenses of $26.3 million and $14.8 million less depreciation of administrative assets of $0.7 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $16.0 million, less depreciation of administrative assets of $0.1 million.

(*) Same as DD&A expenses for the three months ended June 30, 2026 and 2025, six months ended June 30, 2026 and 2025, and the prior quarter (the depreciation of administrative assets had a de minimus amount for all reported periods).

(*) Calculated as DD&A expenses for the three months ended June 30, 2026 and 2025 of $62.3 million and $68.6 million less depreciation of administrative assets of $6.1 million and $2.7 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $132.2 million and $140.8 million less depreciation of administrative assets of $12.0 million and $6.5 million, respectively. For the prior quarter, calculated as DD&A expenses of $69.9 million, less depreciation of administrative assets of $6.0 million.

Operating Netback

(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and reconciliation of this measure.

Operating expenses for the three and six months ended June 30, 2026, decreased by 7% and 4% to $51.6 million and $117.7 million, respectively, compared to the corresponding periods of 2025. The decrease was primarily due to lower workover activities, reduced field personnel costs, lower oil treatment and testing service costs, as well as inventory fluctuations resulting from inventory accumulation at the end of the current quarter.

Operating expenses for the three and six months ended June 30, 2026, on a per boe basis, increased by $1.67 and $0.44 to $17.61 and $17.97, respectively, compared to the corresponding periods of 2025, primarily due to lower sales volumes during current periods, partially offset by $0.18 and $0.68 per boe lower workover activities and inventory fluctuations, respectively.

Compared to the prior quarter, operating expenses decreased by 22% from $66.1 million or by $0.64 from $18.25 on a per boe basis primarily due to inventory fluctuations resulting from inventory accumulation at the end of the current quarter, partially offset by $0.34 per boe higher workover activities.

Transportation expenses

We have options to sell our oil through multiple pipelines and various trucking routes. Each option has varying effects on realized sales price and transportation expenses. The following table shows the percentage of oil, natural gas and NGL volumes we sold in Canada, Colombia and Ecuador using each option for the three and six months ended June 30, 2026 and 2025, and the prior quarter:

Volumes transported through pipeline or via truck receive a higher realized price but incur higher transportation expenses. Conversely, volumes sold at the wellhead have the opposite effect of a lower realized price, offset by lower transportation expenses.

Transportation expenses for the three months ended June 30, 2026, decreased by 13% to $3.9 million, compared to the corresponding period of 2025, due to lower sales volumes transported in Colombia and Canada and increased by $0.04 per boe due to lower sales volumes. Transportation expenses for the six months ended June 30, 2026, increased by 2% or $0.12 per boe due to higher volumes transported via pipeline which had a higher cost per boe.

Transportation expenses decreased by 26% or $0.13 per boe from $5.3 million or $1.46 per boe in the prior quarter due to lower sales volumes transported during the current quarter.

(*)The sales price in Ecuador is the average Brent price less discounts for the month prior to lifting (M-1).

DD&A Expenses

DD&A expenses for the three and six months ended June 30, 2026, decreased by 9% and 6%, respectively, due to lower costs in the depletable base for Canadian operations as a result of Simonette and Lodgepole areas disposition and higher proved reserves across reportable segments compared to the corresponding periods of 2025. On a per boe basis, DD&A expenses for the three and six months ended June 30, 2026, increased by $1.61 and $0.06, respectively, due to the lower sales volumes in the current periods.

DD&A expenses decreased by 11% from $69.9 million and increased by $2.01 on a per boe basis when compared to the prior quarter for the same reason mentioned above.

Asset Impairment

For the three and six months ended June 30, 2026 and 2025, we had no ceiling test impairment losses. We used a 12-month unweighted average of the first-day-of-the-month prices prior to the ending date of the period ended June 30, 2026 as follows: Brent Crude $78.55 per bbl, Edmonton Light Crude of C$98.28 per bbl, Alberta AECO spot price of C$1.55 per MMBtu, Edmonton Propane C$32.84 per boe, Edmonton Butane C$41.70 per boe and Edmonton Condensate C$100.06 per boe (June 30, 2025: Brent Crude of $73.60 per bbl, Edmonton Light Crude of C$91.55 per bbl, Alberta AECO spot price of C$1.69 per MMBtu Edmonton Propane C$33.82 per boe, Edmonton Butane C$47.11 per boe and Edmonton Condensate C$95.75 per boe).

G&A Expenses

G&A expenses before stock-based compensation for the three months ended June 30, 2026, decreased by 6% to $13.2 million compared to the corresponding period of 2025, primarily due to lower consulting and information technology costs during the current period. G&A expenses before stock-based compensation for the six months ended June 30, 2026, increased by 9% to $28.4 million, compared to the corresponding period of 2025, primarily due to higher costs associated with project optimization.

On a per boe basis, G&A expenses before stock-based compensation for the three and six months ended June 30, 2026 increased by $0.47 and $0.61 to $4.52 and $4.33, compared to the corresponding period of 2025 primarily due to 16% and 6% lower sales volumes, respectively.

Compared to the prior quarter, G&A expenses before stock-based compensation decreased by 13% due to lower consulting, information technology costs and lower salaries associated with headcount optimization. On a per boe basis, G&A expenses before stock-based compensation increased by $0.34 compared to the prior quarter due to 20% decrease in sales volumes.

G&A expenses after stock-based compensation for the three months ended June 30, 2026, decreased by 36% or $0.97 per boe compared to the corresponding period of 2025 due to lower share price resulting in stock-based compensation recovery. G&A expenses after stock-based compensation for the six months ended June 30, 2026, increased by 70% or $3.04 per boe compared to the corresponding period of 2025, due to higher stock-based compensation cost attributed to a higher share price during the current period.

Compared to the prior quarter, G&A expenses after stock-based compensation decreased by 73% or $6.37 per boe due to lower share price resulting in stock-based compensation recovery.

Severance Expenses

For the three and six months ended June 30, 2026, severance expenses were $0.1 million and $2.6 million, compared to nil for each of the corresponding periods of 2025 and $2.5 million for the prior quarter, respectively, due to headcount optimization.

Foreign Exchange Gains and Losses

For the three and six months ended June 30, 2026, we had foreign exchange losses of $2.6 million and $4.0 million, compared to $3.7 million and $7.6 million losses on foreign exchange in the corresponding periods of 2025, respectively, and a $1.4 million loss on foreign exchange in the prior quarter. Accounts payable, taxes receivable and payable and deferred income taxes are considered monetary items and require translation from local currencies to U.S. dollar functional currency at each balance sheet date. This translation was the primary source of the foreign exchange gains and losses in the periods.

The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three and six months ended June 30, 2026 and 2025 and the prior quarter:

Financial Instruments Gains or Losses

The following table presents the nature of our financial instruments gains or losses for the three and six months ended June 30, 2026 and 2025, and the prior quarter:

Income Tax Expense

Current income tax expense was $15.0 million for the six months ended June 30, 2026, compared to $10.5 million in the corresponding period of 2025, primarily due to higher taxable income.

The deferred tax for the six months ended June 30, 2026, was a recovery of $21.1 million mainly due to an increase in deductible temporary differences arising from tax losses generated during the period, unrealized hedging losses and accruals. These were partially offset by higher tax depreciation relative to accounting depreciation.

The deferred income tax for the six months ended June 30, 2025, was a recovery of $2.3 million primarily attributable to an increase in deductible temporary differences arising from tax losses generated during the period. This recovery was partially offset by temporary differences related to accelerated tax depreciation in excess of accounting depreciation.

For the six months ended June 30, 2026, the difference between the effective tax rate of 6% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments and other non-deductible expenses. This was partially offset by an increase in the impact of foreign taxes and the 2025 true-up (recovery).

For the six months ended June 30, 2025, the difference between the effective tax rate of negative 34% and the 21% statutory tax rate was primarily due to an increase in the non-deductible foreign translation adjustments, other permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes.

Net (Loss) Income and Funds Flow from Operations (a Non-GAAP Measure)

(1) Funds flow from operations is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in "Financial and Operational Highlights" for a definition and reconciliation of this measure.

Capital expenditures during the three months ended June 30, 2026, were $54.3 million.

During the three months ended June 30, 2026, we drilled the following wells:

During the three months ended June 30, 2026, we spud one development well in Cohembi field in Colombia which was producing as of June 30, 2026.

Liquidity and Capital Resources

We believe that our capital resources, including cash on hand and cash generated from operations will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for the next 12 months, given the current oil price trends and production levels. We may also access capital markets to pursue financing, including for the re-purchase of common stock or the repayment of debt in the future. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us with the flexibility to respond to both internal growth opportunities and those available through acquisitions. We intend to pursue growth opportunities and acquisitions from time to time, which may require significant capital to be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.

Senior Notes

During the six months ended June 30, 2026, we issued $503.6 million in aggregate principal amount of our 9.75% Senior Secured Amortizing Notes due 2031 (the “9.75% Senior Notes”), and paid $125.0 million in cash consideration in exchange for $628.7 million aggregate principal amount of our 9.50% Senior Secured Amortizing Notes due 2029 (the “9.50% Senior Notes”). The exchange was accounted for as debt modification.

The 9.75% Senior Notes will mature on April 15, 2031, unless earlier redeemed or re-purchased. The principal amount of 9.75% Senior Notes is to be repaid as follows: (i) October 15, 2029 - 15% of the principal amount; (ii) October 15, 2030 - 15% of the principal amount; (iii) April 15, 2031 - the remainder of the principal amount. On or before December 31, 2026 (“the Offer Date”), we are required to offer to purchase up to $30.0 million aggregate principal amount of the 9.75% Senior Notes (“the Offer Amount”). The Offer Amount will be reduced by the aggregate principal amount of any 9.75% Senior Notes redeemed or re-purchased by us in the open market transactions before the Offer Date.

During the six months ended June 30, 2026, we re-purchased $9.2 million of 9.75% Senior Notes for cash consideration of $8.1 million resulting in a $0.6 million gain on purchase, which included the write-off of deferred financing fees of $0.5 million. Subsequent to the quarter, we re-purchased an additional $15.0 million of 9.75% Senior Notes for cash consideration of $13.5 million.

At any time, prior to April 15, 2028, we may redeem up to 35% of the aggregate principal amount of 9.75% Senior Notes at a redemption price equal to 109.75% of the principal amount. Additionally, we may redeem all or a portion of the 9.75% Senior Notes on or after 2028 at the following redemption prices: 2028 - 104.875%; 2029 - 102.438%; 2030 and thereafter - 100%.

Under the terms of the 9.75% Senior Notes agreement, we are required to maintain compliance with the following financial covenants:

i.consolidated interest coverage ratio of not less than 2.50; and

ii.consolidated net debt (total debt excluding deferred financing fees less cash equivalents) to consolidated adjusted earnings before interest, taxes and DD&A (“EBITDA”) of not more than 3.00.

As at June 30, 2026, we were in compliance with all applicable covenants related to Senior Notes.

Credit Facility

On May 12, 2026, we, through our wholly owned subsidiary Gran Tierra Canada Ltd., amended our revolving credit facility with National Bank of Canada. As part of the amendment, the borrowing base has decreased to C$75.0 million (US$52.8 million). The available commitment under the revolving credit facility remained unchanged of a C$75.0 million (US$52.8 million), comprised of C$60.0 million (US$42.3 million) syndicated facility and C$15.0 million (US$10.6 million) of operating facility. The drawn down amounts under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00% to 4.00% per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00% to 5.00% per annum. Undrawn amounts under the revolving credit facility bear standby fee ranging from 0.75% to 1.25% per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd. The revolving credit facility matures on October 30, 2027. As of June 30, 2026, the revolving credit facility remained undrawn.

Prepayment agreements

During the six months ended June 30, 2026, we amended our existing prepayment agreement with Trafigura, entering into a new oil prepayment agreement that covers both our Ecuadorian and Colombian oil production. The amended agreement provides for total prepayments of up to $350.0 million, including $325.0 million available immediately and an additional $25.0 million available at Trafigura’s sole discretion. The term of the amended prepayment agreement is 48 months.

Amounts drawn on this prepayment agreement are to be repaid through future oil deliveries. Shortfalls in crude oil deliveries in any given repayment period can be delivered during the next repayment period within three calendar months or paid in cash thereafter. Amounts under the prepayment facility are subject to interest based on SOFR risk-free rate plus a margin of 4.45% per annum. Under the terms of the prepayment agreement, we can repay the outstanding balance of the advance payment at any time without penalty. We were granted a grace period for re-payment of the principal amount drawn under the prepayment agreement with first re-payment starting April 2026.

Pursuant to the amended and restated prepayment agreement, proceeds from the new advance are required to be used exclusively to finance the repurchase or exchange of Senior Notes and to pay fees and expenses associated with the amended agreement.

We are required to maintain compliance with the following financial covenants related to amounts drawn under the prepayment agreement semi-annually, calculated on March 31 and September 30 of each year:

i.Asset Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of certain wholly owned subsidiaries of the Company that sell crude oil, projected through the final maturity date and discounted at 10% over the outstanding principal and the interest payable amount on the prepayment agreement at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 90% of the prevailing ICE Brent forward strip.

ii.Debt Service Coverage Ratio of at least 200%, calculated using the estimated crude oil to be delivered by the Company from any relevant time up to the final maturity date based on 80% of the prevailing ICE Brent forward strip and adjusted for quality differential and transportation discount over the outstanding principal amount under the prepayment agreement.

During the three and six months ended June 30, 2026, we drew nil and $166.5 million on oil prepayment and re-paid $28.8 million of the outstanding principal on oil prepayment via crude oil deliveries.

As at June 30, 2026, there was $287.7 million outstanding (December 31, 2025 - $150.0 million) on the oil prepayment agreement. Of this amount, $86.3 million (December 31, 2025 - $34.1 million) was classified as a current portion and included in accounts payable and accrued liabilities on our condensed consolidated balance sheet.

Assets exchange transaction

During the three months ended June 30, 2026, we completed an asset exchange transaction in which we transferred a 30% WI in certain oil and natural gas rights, wells, and tangible assets located in the Marten Hills area, in exchange for oil and natural gas rights, wells, and tangible assets in the Seal/Dawson area, WI ranging from 35% to 100%. In connection with this transaction, we received cash consideration of C$0.8 million (US$0.6 million).

Disposition of Lodgepole area

During the three months ended June 30, 2026, we completed a disposition of 54% WI and associated title rights in the Lodgepole area in Canada effective January 1, 2026, for a total cash consideration of C$12.8 million (US$9.3 million). As part of disposition, we derecognized asset retirement obligation attributed to Lodgepole area totaling C$17.5 million (US$12.8 million) on an undiscounted basis and C$9.0 million (US$6.6 million) on a discounted basis. No gain or loss was recognized in the statement of operations as the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.

Disposition of Simonette area

During the six months ended June 30, 2026, we disposed of the entire working interest and associated title rights in the Simonette Montney area in Canada effective January 1, 2026, for total cash consideration of C$66.3 million (US$48.6 million). No gain or loss was recognized in the statement of operations because the disposal did not materially change the relationship between capital costs and the proved reserves of oil and natural gas assets.

Partnership with Ecopetrol S.A.

During the six months ended June 30, 2026, we entered into a strategic partnership with Ecopetrol S.A. to earn, subject to regulatory approvals and conditions precedent, a 49% WI in the Tisquirama Block in Colombia. Under the terms of the agreement, we have committed to fund approximately $47.1 million of a $92.4 million gross capital program over 40 months, including a minimum Phase 1 investment of $15.0 million. Upon completion of Phase 1, we will be entitled to 49% of production and are expected to assume operatorship. On May 27, 2026, we satisfied all outstanding conditions precedent to the partnership agreement and received regulatory approval.

Production sharing agreement (“PSA”)

During the six months ended June 30, 2026, we, through our wholly owned subsidiary, Gran Tierra Energy (Azerbaijan) GmbH, entered into an exploration, development and PSA with the State Oil Company of Azerbaijan Republic (“SOCAR”), providing for a 65% participating interest to us and a 35% participating interest to SOCAR. The PSA provides for a five-year exploration phase and, in the event of a commercial crude oil discovery, a 25-year development phase, with minimum work commitments during the exploration period to be completed within 36 months. These commitments include, among others, the acquisition of 250 square kilometers of 3D seismic data, the drilling of two exploration wells, and the conduct of geological and environmental impact studies. We have the right to relinquish the entire contract area during the exploration phase upon fulfillment of our exploration commitments, subject to 90 days’ prior notice to SOCAR.

Derivative positions

As at June 30, 2026, we had outstanding commodity price derivative positions as follows:

As at June 30, 2026, we had the following outstanding foreign currency exchange derivative positions:

(1) At the June 30, 2026 foreign exchange rate.

Cash Flows

The following table presents our primary sources and uses of cash and cash equivalents and restricted cash and cash equivalents for the periods presented:

(1) Adjusted EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to footnote 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and reconciliation of this measure.

One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices. Sales volume changes, costs related to operations and debt transactions also impact cash flows. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes. During the three months ended June 30, 2026, funds flow from operations increased by 12% compared to the corresponding period of 2025, due to an increase in benchmark oil prices, lower operating expenses, partially offset by lower sales volumes, higher cash settlements on derivative instruments and higher current income tax expense. During the six months ended June 30, 2026, funds flow from operations decreased by 6% compared to the corresponding period of 2025, primarily due to lower sales volumes, higher cash settlements on derivative instruments and higher current income tax expense, partially offset by an increase in benchmark oil prices and lower operating expenses.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2025 Annual Report on Form 10-K and have not changed materially since the filing of that document.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity price risk

Our principal market risk relates to oil, natural gas and NGL prices which are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Our revenues are from oil sales at Brent, or Edmonton Light pricing and for gas at AECO pricing and adjusted for quality. As at June 30, 2026, we have entered into commodity price derivative contracts to manage the variability in cash flows associated with the forecasted sale of our oil production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending.

Foreign currency risk

Foreign currency risk is a factor for our Company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 85% of our revenues are related to the U.S. dollar price of Brent with the remainder related to Canadian dollar price of WTI oil or AECO gas. In Colombia and Ecuador, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures is in U.S. dollars or is based on U.S. dollar prices. The majority of our operating costs, income taxes, VAT, and G&A expenses in all locations are in

local currency. In Canada, we receive 100% of our revenue in Canadian dollars and the majority of our capital and operating expenditures are in Canadian dollars or are based on Canadian dollar prices.

We have entered into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs.

Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our accounts payable, taxes receivable and payable and deferred tax assets and liabilities in Colombia are denominated in the local currency of the Colombian foreign operations which are our monetary assets. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency.

Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our revolving Canadian credit facility which bears floating rates of interest. As of June 30, 2026, the revolving credit facility remained undrawn.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l3a-15(b) of the Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra’s disclosure controls and procedures were effective as of June 30, 2026.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended June 30, 2026, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II - Other Information

Item 1. Legal Proceedings

See Note 11 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for any material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 2025, and any material matters that have arisen since the filing of such report.

Item 1A. Risk Factors

There are numerous factors that affect our business and results of operations, many of which are beyond our control. In addition to information set forth in this Quarterly Report on Form 10-Q, including in Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, you should carefully read and consider the factors set out in Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025. These risk factors could materially affect our business, financial condition and results of operations. The unprecedented nature of ongoing conflicts in several parts of the world, along with volatility in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

(1) On November 3, 2025, we implemented a share re-purchase program (the “2025 Program”) through the facilities of the TSX, the NYSE American or alternative programs in Canada or the United States commencing November 6, 2025 and ending on November 5, 2026. Under the 2025 Program, we are able to purchase at prevailing market prices up to 2,925,720 shares of Common Stock, representing approximately 10% of the public float as of October 31, 2025.

Item 5. Other Information

During the three months ended June 30, 2026, no director or Section 16 officer adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408(a) of Regulation S-K).

Item 6. Exhibits

101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH Inline XBRL Taxonomy Extension Schema Document

101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document

104.The cover page from Gran Tierra Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2026, formatted in Inline XBRL (included within the Exhibit 101 attachments).